Fouling is generally defined as the accumulation of unwanted materials on the surfaces of processing equipment. In petroleum processing, fouling is the accumulation of unwanted hydrocarbon-based deposits on heat exchanger surfaces. It has been recognized as a nearly universal problem in design and operation of refining and petrochemical processing systems, and affects the operation of equipment in two ways. First, the fouling layer has a low thermal conductivity. This increases the resistance to heat transfer and reduces the effectiveness of the heat exchangers. Second, as deposition occurs, the cross-sectional area is reduced, which causes an increase in pressure drop across the apparatus and creates inefficient pressure and flow in the heat exchanger.
Fouling in heat exchangers associated with petroleum type streams can result from a number of mechanisms including chemical reactions, corrosion, deposit of insoluble materials, and deposit of materials made insoluble by the temperature difference between the fluid and heat exchange wall. For example, the inventors have shown that a low-sulfur, low asphaltene (LSLA) crude oil and a high-sulfur, high asphaltene (HSHA) crude blend are subject to a significant increase in fouling when in the presence of iron oxide (rust) particulates, as shown for example in FIGS. 1 and 2.
One of the more common root causes of rapid fouling, in particular, is the formation of coke that occurs when crude oil asphaltenes are overexposed to heater tube surface temperatures. The liquids on the other side of the exchanger are much hotter than the whole crude oils and result in relatively high surface or skin temperatures. The asphaltenes can precipitate from the oil and adhere to these hot surfaces. Another common cause of rapid fouling is attributed to the presence of salts and particulates. Salts/particulates can precipitate from the crude oils and adhere to the hot surfaces of the heat exchanger. Inorganic contaminants play both an initiating and promoting role in the fouling of whole crude oils and blends. Iron oxide, calcium carbonate, silica, sodium and calcium chlorides have all been found to be attached directly to the surface of fouled heater rods and throughout the coke deposit.
Prolonged exposure to such surface temperatures, especially in the late-train exchangers, allows for the thermal degradation of the organics and asphaltenes to coke. The coke then acts as an insulator and is responsible for heat transfer efficiency losses in the heat exchanger by preventing the surface from heating the oil passing through the unit. Salts, sediment and particulates have been shown to play a major role in the fouling of pre-heat train heat exchangers, furnaces and other downstream units. Desalter units are still the only opportunity refineries have to remove such contaminants and inefficiencies often result from the carryover of such materials with the crude oil feeds.
Blending of oils in refineries is common, but certain blends are incompatible and cause precipitation of asphaltenes that can rapidly foul process equipment. Improper mixing of crude oils can produce asphaltenic sediment that is known to reduce heat transfer efficiency. Although most blends of unprocessed crude oils are not potentially incompatible, once an incompatible blend is obtained, the rapid fouling and coking that results usually requires shutting down the refining process in a short time. To return the refinery to more profitable levels, the fouled heat exchangers need to be cleaned, which typically requires removal from service, as discussed below.
Heat exchanger in-tube fouling costs petroleum refineries hundreds of millions of dollars each year due to lost efficiencies, throughput, and additional energy consumption. With the increased cost of energy, heat exchanger fouling has a greater impact on process profitability. Petroleum refineries and petrochemical plants also suffer high operating costs due to cleaning required as a result of fouling that occurs during thermal processing of whole crude oils, blends and fractions in heat transfer equipment. While many types of refinery equipment are affected by fouling, cost estimates have shown that the majority of profit losses occur due to the fouling of whole crude oils, blends and fractions in pre-heat train exchangers.
Heat exchanger fouling forces refineries to frequently employ costly shutdowns for the cleaning process. Currently, most refineries practice off-line cleaning of heat exchanger tube bundles by bringing the heat exchanger out of service to perform chemical or mechanical cleaning. The cleaning can be based on scheduled time or usage or on actual monitored fouling conditions. Such conditions can be determined by evaluating the loss of heat exchange efficiency. However, off-line cleaning interrupts service. This can be particularly burdensome for small refineries because there will be periods of non-production.
Naphthenic acids are carboxylic acids that occur in most crude oils as trace components and in some, biodegraded oils in significantly greater concentrations. Total acids in crude oils is semi-quantified by titration with KOH and expressed in terms of total acid number (TAN). The acidity of high TAN oils may cause emulsion and corrosion problems in both production and refining. Solid deposits recently identified as sodium and calcium naphthenates can result in substantial damage and loss of production.
Under certain conditions, the naphthenic acids present in acidic crude oil will precipitate with Ca2+ ions that are present in the co-produced water to form calcium naphthenate solids. Other cations are involved to a lesser extent forming a variety of metal naphthenates (e.g., sodium, ferrous iron and magnesium). This solid precipitation accumulates predominantly in oil-water separators and desalters, but naphthenates can also deposit in the tube and pipelines.
A great deal of research has been pursued to characterize the naphthenic acid responsible for the calcium deposits. It has been recently found that a specific family of high molecular weight tetracarboxylic acids, termed ARN Acids, is the major constituents responsible for the calcium naphthenate deposits (ARN is not an acronym, but is Old Norwegian for “eagle”). ARN acids are high molecular weight molecules with four carboxylic acid groups, each at the end of a long aliphatic chain, forming a four-fingered molecule with polar tips. The ARN acids are a specific family of ˜C80 tetracarboxylic acids. A majority of the ARN acids have a molecular weight ranging from about 1228 to about 1236 atomic mass units (amu) with one of the main acids having a molecular weight of 1232 amu and a molecular formula of C80H142O8. The ARN acids do not have an aromatic or alkene function present and quaternary carbons do not exist. The ARN acids can have 4-8 sites of unsaturation (or 4-8 cyclopentyl rings) and are believed to be derived from archaeal C80 lipids.
The proposed structure of a major ARN acid with mass 1232 is 6:17,10:18,10′:18′,6″:17″,10″:18″,10″:18″)-hexacyclo-20-bis-16,16″-biphytane-1,1′,1″,1′″-tetracarboxylic acid. The molecule contains two biphytanyl diacids, each with three pentacyclic rings joined together by a linkage at the C20 methyl groups, as described in Lutnaes B. F., Brandal Ø., Sjöblom J., and Krane J. (2006) Archaeal C80 isoprenoid tetraacids responsible for naphthenate deposition in crude oil processing. Organic & Biomolecular Chemistry 4, 616-620, incorporated by reference in its entirety herein.
A representative structure of an archaeal C80 isoprenoid tetra-acid is shown below:

The four carboxylic acid groups afford the molecule's unusually high reactivity. The four carboxylic groups tend to create polymeric salt when they are coordinated with divalent metal ions. This weaved polymeric-like structure yields a very sticky deposit that hardens upon contact with air.
The need exists to be able to prevent the precipitation/adherence of particulates and asphaltenes from the heated surfaces before the particulates can promote fouling and the asphaltenes become thermally degraded or coked. The coking mechanism requires both temperature and time. The time factor can be greatly reduced by keeping the particulates away from the surface and by keeping the asphaltenes in solution. Such reduction and/or elimination of fouling will lead to increased run lengths (less cleaning), improved performance and energy efficiency while also reducing the need for costly fouling mitigation options.